Publisher Summary
This chapter describes the terms primary oil recovery, secondary oil recovery, and tertiary oil recovery which are traditionally used to describe hydrocarbons recovered according to the method of production. Primary oil recovery describes the production of hydrocarbons under the natural driving mechanisms present in the reservoir without supplementary help from injected fluids such as gas or water. However, the lack of sufficient natural drive in most reservoirs has led to the practice of supplementing the natural reservoir energy by introducing some form of artificial drive, the most basic method being the injection of gas or water. Oil recovery refers to the additional recovery that result from the conventional methods of water-injection and immiscible gas injection. Usually, the selected secondary recovery process follows the primary recovery but it can also be conducted concurrently with the primary recovery. Water flooding is perhaps the most common method of secondary recovery. However, before undertaking a secondary recovery project, it should be clearly proven that the natural recovery processes are insufficient. Otherwise, there is a risk that the substantial capital investment required for a secondary recovery project may be wasted.

Chapter 14 – Principles of Waterflooding

Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock. In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, reinjection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created. To the best of our knowledge, there are no data in the literature concerning the influence of in situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (nondissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, eit...

Effect of Continuous, Trapped, and Flowing Gas on Performance of Alkaline Surfactant Polymer (ASP) Flooding

The optimum gas saturation is defined as that free gas saturation needed to achieve maximum oil recovery by waterflooding and primary depletion. This paper presents an investigation to develop a relationship between the optimum free gas saturation at which to waterflood a reservoir and the properties of the fluids and the rock. The optimum gas saturations for various rock-fluid systems were obtained from the literature and from previously unpublished sources. Distribution of the rock and fluid systems assures a good representation of reservoirs where the effects of free gas saturation will be most benefical. A multiple regression analysis program written for the IBM 7094 digital computer is used to compare numerous equations and to calculate their coefficients. The final equation containing 4 coefficients results in an average absolute deviation of 4.6% for all the sets of data. The correlation developed is useful to predict the optimum gas saturation at which maximum oil recovery is obtained from variables that normally are measured either in the laboratory or in the field. Finally, an example calculation based on actual reservoir rock and fluid properties is presented. (26 refs.)

C. Khelil

Papers

Correlation of optimum free gas saturation with rock and fluid properties